Case History of Water Pressure Maintenance Operations in the McComb Unit
- Paul B. Fletcher (Sun Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1967
- Document Type
- Journal Paper
- 457 - 463
- 1967. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 5.4.2 Gas Injection Methods, 5.2.1 Phase Behavior and PVT Measurements, 5.7.2 Recovery Factors, 5.7 Reserves Evaluation, 2.2.2 Perforating, 5.4.1 Waterflooding, 4.2 Pipelines, Flowlines and Risers, 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.1.5 Processing Equipment, 1.6 Drilling Operations, 5.2 Reservoir Fluid Dynamics, 3.1.6 Gas Lift, 2 Well Completion, 4.1.9 Tanks and storage systems
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This paper covers the case history of the McComb field in Pike County, Miss., from discovery through development, unitization and water pressure maintenance operations. McComb unitization was unique since it was consummated prior to the productive limits of the lower Tusaloosa oil reservoir being defined; productive limits were defined, at the expense of working interest owners of producing tracts, within the first 6 months of unitized operations. Also the McComb unit was most unusual since it was formed to waterflood an 11,000-ft oil sand known to contain a water saturation of 60 percent of total per volume. Under water pressure maintenance operations it was estimated that approximately 39 percent of the original inplace oil would be recovered, of which 21 percent was attributed to the injection of extraneous water. Current studies indicate the ultimate oil recovery will be in the order of 42 percent.
The McComb field was saved from certain financial disaster through early unitization and water pressure maintenance. Early in the development of the field many unpleasant factors began to appear in the accumulation of the McComb data. Most of the data assembled gave signals that all was not well and that the performance of the McComb Lower Tuscaloosa oil reservoir would undoubtedly deteriorate at an early date unless corrective measures were taken. Some of the alarm signals consisted of low porosity, high water saturation of the producing sand, high formation volume factor, high gas saturation pressure, thin sand conditions and the exceptionally rapid decline of reservoir pressure as development progressed. It was obvious that something had to be done quickly to stop the rapid pressure decline of the reservoir or the field would be reduced to a salvage stage prior to complete development. To put a fluid injection program into operation, a unique plan of unitization was adopted at the time the field was only partially developed.
The McComb field is located on the west side of the city of McComb in Pike County, Miss.. and is approximately 75 miles south-southwest of Jackson on U. S. Highway 51.
Discovery and Development
The McComb discovery well, the Gillis-Pope No.1, was spudded July 8 and completed Aug. 8, 1959, at a total depth of 11,219 ft. Sixteen net feet of Lower Tuscaloosa oil sand was encountered at a depth of 10,870 to 10,886 ft. The well was completed by perforating 5 1/2 -in. casing in the bottom 4 ft of the oil section. On Aug. 8, 1959, the Gillis-Pope No. 1 was potentialed on a 9/64 -in. choke and flowed 231 BOPD with a gas-oil ratio of 1,360:1, oil gravity 42.5 deg API, flowing tubing pressure 1,625 psig and no water. Based on the performance of the discovery well, it appeared that an excellent oil field had been discovered. By the end of Dec., 1959, there were 15 producers completed on 40-acre spacing. Drilling activities gained momentum and by early 1960, producing wells were being completed at the rate of 20 to 25 per month. Drilling and completion time required approximately 25 days per well.
The accelerated drilling program prompted the rapid accumulation of reservoir data. The first information obtained was the original reservoir pressure which measured 4,904 psig at a subsea datum of - 10,493 ft. One major company cored practically all of its drilling wells. Laboratory analyses of all cores showed that water content of the producing sand averaged 60 percent of total pore volume. Fig. 1 shows the relationship between permeability and irreducible water saturation of cores from the "B" oil sand. The field average of 91.1 md and 60 percent water saturation are in close agreement with this curve. Reservoir fluid analyses and core data supported a calculation of only 380 STB of oil originally in place per net acre-foot of sand (Table 1). This relatively small amount of oil content per net acre-foot of sand was quite startling and disturbing to all associated with the McComb field.
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